Electric Submersible Pump Assembly

ABSTRACT

Disclosed herein are electric submersible pump assemblies and methods for pumping wellbore fluid that may each include an electric submersible pump assembly which may include: a shroud that may include: a first shroud aperture; and a second shroud aperture; a first pump disposed in the shroud, wherein the first pump may be capable of pumping wellbore fluid that has flowed through the first shroud aperture; and a second pump disposed in the shroud, wherein the second pump may be capable of pumping out of the second aperture wellbore fluid that has flowed through the first shroud aperture.

BACKGROUND 1. Field of Inventions

The field of this application and any resulting patent is electricsubmersible pumps.

2. DESCRIPTION OF RELATED ART

Various electric submersible pump assemblies and methods for pumpingfluids from a wellbore have been proposed including prior art ofelectric submersible pump assemblies listed on this patent. However,those assemblies and methods lack the combination of steps and/orfeatures of the assemblies and methods claimed herein. Furthermore, itis contemplated that the assemblies and/or methods disclosed herein,including those claimed, solve at least some of the problems those priorart assemblies and methods have failed to solve. Also, it iscontemplated that the assemblies and/or methods claimed herein havebenefits that would be surprising and unexpected to a hypotheticalperson of ordinary skill with knowledge of the prior art existing as ofthe filing date of this application.

SUMMARY

The disclosure herein includes electric submersible pump assemblies andmethods for pumping wellbore fluid that may each include an electricsubmersible pump assembly which may include: a shroud that may include:a first shroud aperture; and a second shroud aperture; a first pumpdisposed in the shroud, wherein the first pump may be capable of pumpingwellbore fluid that has flowed through the first shroud aperture; and asecond pump disposed in the shroud, wherein the second pump may becapable of pumping out of the second aperture wellbore fluid that hasflowed through the first shroud aperture.

Additionally, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatmay include: a first shroud portion; and a second shroud portion; afirst pump disposed in the shroud, wherein the second pump is capable ofpumping wellbore fluid past the first shroud portion; and a second pumpdisposed in the shroud wherein the second pump is capable of pumpingwellbore fluid out through the second shroud portion.

Also, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatmay include: a first shroud aperture; and a second shroud aperture; afirst pump disposed in the shroud; a second pump disposed in the shroud,wherein the second pump may be capable of pumping wellbore fluid out ofthe second shroud aperture; a motor; and a shaft rotatably coupled tothe motor, the first pump, and the second pump.

Further, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud; afirst pump disposed in the shroud; a second pump disposed in the shroud;and an intake conduit disposed between the first pump and the secondpump, wherein the intake conduit may have: a first intake aperture influid communication with the first pump; and a second intake aperture influid communication with the second pump.

In addition, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatthat may include: a first shroud portion having a first shroud aperture;and a second shroud portion having a second shroud aperture; a firstpump disposed in the shroud, wherein the first pump may be capable ofpumping wellbore fluid that have flowed pass the second shroud portionand then through the first shroud aperture; and a second pump disposedin the shroud.

Furthermore, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatthat may include: a first shroud portion having a first shroud aperturecapable of receiving wellbore fluid therethrough; and a second shroudportion having a second shroud aperture capable of receiving wellborefluid therethrough; a first pump disposed in the shroud; a second pumpdisposed in the shroud; an intake conduit disposed between the firstpump and the second pump, the intake conduit having: a first intakeaperture, wherein the first pump may receive wellbore fluid entering thefirst intake aperture; and a second intake aperture, wherein the secondpump may be capable of receiving wellbore fluid that have flowed throughthe second intake aperture; a motor; a shaft rotatably coupled to themotor, the first pump, and the second pump.

Moreover, the disclosure herein includes methods for pumping wellborefluid that may each include: providing an electric submersible pumpassembly that may include: a shroud that may include: a first shroudportion; and a second shroud portion; a first pump disposed in theshroud; and a second pump disposed in the shroud; drawing wellbore fluidfrom the wellbore into the shroud; pumping, with the first pump, aportion of the wellbore fluid in the shroud in a first direction;pumping, with the second pump, a portion of the wellbore fluid in theshroud in a second direction, opposite the first direction.

The disclosure herein includes methods for pumping wellbore fluid thatmay each include: providing an electric submersible pump assembly thatmay include: a shroud that may include: a first shroud aperture; and asecond shroud aperture; a first pump disposed in the shroud; a secondpump disposed in the shroud; a motor; and a shaft rotatably coupled tothe motor, the first pump, and the second pump; rotating the shaft withmotor; actuating the first pump and the second pump with the rotatingshaft; pumping, with the actuated first pump, wellbore fluid in a firstdirection; pumping, with the actuated second pump, wellbore fluid in theshroud in a second direction, opposite the first direction.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a cross-sectional side view of an electricalsubmersible pump assembly disposed in a wellbore.

FIG. 2 illustrates a cross-sectional side view of a production pump.

FIG. 3 illustrates a cross-sectional side view of an intake conduitdisposed in a shroud.

FIG. 4 illustrates a cross-sectional side view of an inverted pump.

FIG. 5 illustrates a cross-sectional side view of a packer disposed in ashroud.

FIG. 6 illustrates a cross-sectional side view of a discharge conduitdisposed in shroud.

DETAILED DESCRIPTION 1. Introduction

A detailed description will now be provided. The purpose of thisdetailed description, which includes the drawings, is to satisfy thestatutory requirements of 35 U.S.C. § 112. For example, the detaileddescription includes a description of inventions defined by the claimsand sufficient information that would enable a person having ordinaryskill in the art to make and use the inventions. In the figures, likeelements are generally indicated by like reference numerals regardlessof the view or figure in which the elements appear. The figures areintended to assist the description and to provide a visualrepresentation of certain aspects of the subject matter describedherein. The figures are not all necessarily drawn to scale, nor do theyshow all the structural details, nor do they limit the scope of theclaims.

Each of the appended claims defines a separate invention which, forinfringement purposes, is recognized as including equivalents of thevarious elements or limitations specified in the claims. Depending onthe context, all references below to the “invention” may in some casesrefer to certain specific embodiments only. In other cases, it will berecognized that references to the “invention” will refer to the subjectmatter recited in one or more, but not necessarily all, of the claims.Each of the inventions will now be described in greater detail below,including specific embodiments, versions, and examples, but theinventions are not limited to these specific embodiments, versions, orexamples, which are included to enable a person having ordinary skill inthe art to make and use the inventions when the information in thispatent is combined with available information and technology. Variousterms as used herein are defined below, and the definitions should beadopted when construing the claims that include those terms, except tothe extent a different meaning is given within the specification or inexpress representations to the Patent and Trademark Office (PTO). To theextent a term used in a claim is not defined below or in representationsto the PTO, it should be given the broadest definition persons havingskill in the art have given that term as reflected in at least oneprinted publication, dictionary, or issued patent.

2. Selected Definitions

Certain claims include one or more of the following terms which, as usedherein, are expressly defined below.

The term “adjacent” as used herein means next to and may includephysical contact but does not require physical contact.

The term “aligning” as used herein is defined as a verb that meansmanufacturing, forming, adjusting, or arranging one or more physicalobjects into a particular position. After any aligning takes place, theobjects may be fully or partially “aligned.” Aligning preferablyinvolves arranging a structure or surface of a structure in linearrelation to another structure or surface; for example, such that theirborders or perimeters may share a set of parallel tangential lines. Incertain instances, the aligned borders or perimeters may share a similarprofile.

The terms “annular barrier” and “barrier” mean any structure that whendisposed in a wellbore, e.g., an annular space within a wellbore, iscapable of preventing, inhibiting, or impeding the passage of fluid,e.g., reservoir water, past the structure from one part of the wellbore,e.g., one part of the annular space (e.g., above the structure) toanother part of the wellbore, e.g., another part of the annular space(e.g., below the structure). At least one non-limiting example of anannular barrier is a seal which is preferably a packer. A “seal” isdefined as an annular barrier that when disposed in an annular space hassealing contact with the surfaces forming the annular space and thusprovides a seal that helps in the prevention of fluid passing past theseal from one part of the annular space (e.g., a first annular space) toanother part of the annular space (e.g., a second annular space). Atleast one non-limiting example of a seal is a packer.

The term “annular space” means any space having an annular form, e.g.,the cylindrical space between the inside surface of a wall of an outerconduit, e.g., a shroud illustrated in FIG. 1A, and an outside surfaceof a wall of an inner conduit, e.g., a string of electric submersiblepump assembly components illustrated in FIG. 1A. As discussed below, anannular space may also include multiple annular spaces, e.g., a firstannular space, which may also be referred to as an upper annular space,and a second annular space, which may also be referred to as a lowerannular space.

The term “aperture” as used herein is defined as any opening in a solidobject or structure. For example, an aperture may be an opening thatbegins on one side of the solid object and ends on the other side of theobject. An aperture may alternatively be an opening that does not passentirely through the object, but only partially passes through, e.g., agroove. An aperture can be an opening in an object that is completelycircumscribed, defined, or delimited by the object itself.Alternatively, an aperture can be an opening in the object formed whenthe object is combined with one or more other objects or structures. Oneor more apertures may be disposed and pass entirely through a casing, aconduit, and/or a pump. An aperture may receive another object andpermit ingress and/or egress of the object through the aperture.Non-limiting examples of apertures herein are perforations, entry ports,and exit ports.

The term “assembly” as used herein is defined as any set of componentsthat have been fully or partially assembled together. A group ofassemblies may be coupled to form a combined assembly, e.g., a bodyhaving an inner surface and an outer surface.

The term “bearing assembly” as used herein is defined as an assemblycapable of supporting a shaft assembly as it rotates. In some cases, abearing assembly does not physically touch a shaft assembly. A bearingassembly may be disposed concentrically around a shaft assembly, asshown in FIGS. 3, 4A, 5, and 6 . A bearing assembly may include abushing, e.g., a sleeve. A bearing assembly may receive a rotatableshaft assembly therethrough, in which a clearance may exist betweensurfaces of the bearing assembly and the shaft. A bearing assembly mayinclude an axial support bearing, a journal bearing, or a thrustbearing. A bearing assembly may be disposed at each end of a shaftassembly. A bearing assembly may be disposed on a rotor, Two bearingassemblies may be disposed on a rotor, separated by a length of therotor between the bearing assemblies.

The term “axis” as used herein is defined as any actual or imaginaryline running through the center of an object or structure.

The term “conduit” as used herein is defined as a structure throughwhich a channel is provide for fluid to flow. A conduit may include ashroud, a motor, a packer, and a tubular.

The term “coupled” as used herein is defined as directly or indirectlyconnected, attached, or integral with, e.g., part of. A first object maybe coupled to a second object such that the first object is positionedat a specific, or pre-determined, location and orientation with respectto the second object. For example, a housing in which is disclosed animpeller may be coupled at the upper end to a conduit, e.g., the “secondconduit” disclosed elsewhere herein. A first object may be eitherpermanently or removably coupled to a second object. Two objects may be“permanently coupled” to each other via adhesive or welding; or they maybe “removably coupled” via collets, screws, threading, or nuts and boltssuch that they are capable of being easily separated and no longercoupled. Thus, a portion of a housing may be removably coupled to a sealsuch that the portion of the housing may then be uncoupled and removedfrom the seal. Two objects may be “rotatably coupled” together, e.g.,where a first object may be rotated relative to a second object. Forexample, a shaft may be rotatably coupled to a body in a pump where theshaft may be rotated relative to the body. Two objects may be “sealinglycoupled,”, e.g., where a first object may be abutted to a second objectsuch that respective adjacent surfaces of the objects would be inhibitedfluid from flowing therebetween. For example, a seal may be sealinglycoupled to a fluid conduit where, in some cases, fluid cannot flowbetween adjacent surfaces of the seal and fluid conduit.

The term “cylindrical” as used herein is defined as shaped like acylinder, e.g., having straight parallel sides and a circular or oval orelliptical cross-section. A cylindrical body or structure, e.g.,housing, shaft assembly, or bearing assembly, may be completely orpartially shaped like a cylinder. A cylindrical body, e.g., shaftassembly or housing, which has an outer diameter that changes abruptlymay have a radial face or “lip” extending toward the center axis. Acylindrical body may have an aperture, e.g., borehole, which extendsthrough the entire length of the body to form a hollow cylinder that iscapable of permitting fluid to pass through, e.g., water or hydrocarbon.On the other hand, a cylindrical structure may be solid, e.g., rod orpeg. A drive shaft assembly is an example of a solid cylindrical body.

The term “disposed” as used herein means having been put, placed,positioned, inserted, or oriented in a particular location. For example,when a second conduit occupies a position within a first conduit, thesecond conduit is disposed in or within the first conduit. Also, aconduit or some other type of structure or aperture may be disposed onor disposed adjacent another structure or space.

The term “electric submersible assembly” means an assembly of componentsthat include one or more shrouds, pumps, motors, conduits, and sensorsthat are disposed in a wellbore.

The term “elongated” as used herein describes something that has alength and width wherein the length is greater than the width and ispreferably 5 or more times as long as it is wide. For example, the firstand second conduits, and the first and second annular spaces disclosedherein are “elongated” given their lengths are substantially greaterthan their widths, e.g., outer diameters.

The term “entry port” means an aperture in a structure, e.g., a housingor a wall of a structure, through which fluid, e.g., reservoir fluid, iscapable of passing, from outside the structure to the interior of thestructure.

The term “exit port” means an aperture in a structure, e.g., a housingor a wall of a structure, through which fluid, e.g., reservoir fluid,passes from the interior of the structure, e.g., the housing or conduit,to outside the structure. A “discharge port” may be an exit port.

The terms “first,” “second,” “third,” and other ordinal terms, when usedto refer to certain things, e.g., structures, are terms thatdifferentiate those things from one another and do not mean or implyanything in terms of importance, sequence, etc.

The term “flow” as used herein, as a verb, noun, or word that modifiesanother word, e.g., volume, describes or refers to the moving, or themovement or passage of a fluid, preferably substantially in a particulardirection. For example, reservoir fluid may flow in a downward directionin the interior of a conduit or an annular space. Such flow can belaminar or turbulent, or a combination of laminar and turbulent. Flowvolume in that context may be measured in a variety of units, e.g.,gallons or liters. Time may be measured in seconds, minutes, or hours.

The term “fluid” as used herein is defined as a material that is capableof flowing. A fluid may be a liquid or a gas or some mixture of liquidand gas. A fluid may absorb heat. A fluid has inherent properties whichmay in certain embodiments are measurable, such as viscosity,anti-foaming, thermal stability, thermal conductivity, and thermalcapacity.

The term “horizontal wellbore” as used herein is defined as a wellborethat has been drilled using some type of directional drilling techniqueand includes at least a portion that is more than 45 degrees fromvertical. However, at least a portion of any horizontal wellbore isvertical or at least substantially vertical, as the term “vertical” isused in the oil and gas industry, i.e., pointed toward the center of theearth. For example, the upper portion of the wellbore closest to thesurface is typically vertical, or substantially vertical, and the lowerportion is less vertical and closer to perfectly horizontal relative tothe earth's surface above that portion of the wellbore. For example, ahorizontal wellbore may include a wellbore that is formed as a kick-outwellbore from an originally drilled vertical wellbore. Any horizontalwellbore mentioned herein is defined to include a “heel,” which is thepart, point, or section of the wellbore where the portion of thewellbore changes from being vertical to being horizontal, and the “toe”which refers to the end of the wellbore. In any discussion of wellboresherein, there is no restriction in length unless stated specificallyotherwise, a central part of any elongated space, such as a conduit.

The term “impeller” as used herein is defined as a structure that ispart of a pump, and that is capable of rotating relative to some otherstructure, surface, body and/or a housing. An impeller, when rotating,may cause flow of fluid, e.g., water, lubricant, or hydrocarbon. Animpeller may be coupled to a rotatable shaft. One or more impellers maybe disposed in a pump.

The term “perforation” means an aperture created as a result ofperforating.

The term “port” as used herein is defined as an aperture in a structurefor providing the ingress or egress of fluid.

The term “pressure” as used herein means force(s), including but notlimited to the forces exerted in every direction in an enclosed space,e.g., forces applied against the inside surfaces of any structuredefining the enclosed space. Pressure may be, for example, exertedagainst a surface of an object, e.g., rotor, piston head, seat, and/ordart, from the fluid flow across the surface. Non-limiting examples ofpressure include: (a) the formation pressure in a reservoir, includingthe formation pressure of the upper part of the reservoir adjacent toone or more of the upper perforations in the upper part of the firstconduit, e.g., the upper part of the casing; (b) pressure in one of theannular spaces inside the wellbore, e.g., the pressure in the firstannular space, between the inner surface of the upper part of the firstconduit, e.g., the casing, and the outer surface of the upper part ofthe second conduit, and above the seal (e.g., packer); (c) pressureinside the second conduit; (d) pressure inside the second annular space,between the inner surface of the lower part of the first conduit, e.g.,the lower part of the casing, and the outer surface of the lower part ofthe second conduit, and below the seal (e.g., packer); and (e) theformation pressure of the lower part of the reservoir adjacent to one ormore of the lower perforations in the first conduit, e.g., the lowerpart of the casing. Although pressure is normally measured inkilopascals, kilopascals can be converted to joules, as a unit ofenergy, to combine with potential energy. Thus, pressure (measured injoules) and potential energy (measured in joules) in a reservoir may becombined.

The term “providing” as used herein is defined as making available,furnishing, supplying, equipping, or causing to be placed in position.

The term “reservoir” as used herein is defined as a volumetric spacethat contains fluid, e.g., lubricant, or is capable of containing fluid.A reservoir may be used to store fluid. A reservoir may be artificial orman-made, i.e., manufactured by humans, or it may be natural, i.e.,existing in nature, such as an underground reservoir containing water orhydrocarbons. An example of a natural reservoir may be a body of rockand/or sediment that holds groundwater (also known as an aquifer). Anartificial fluid reservoir may be defined by a housing, e.g., havingwalls. A reservoir may become depleted of material, e.g., hydrocarbon,which was once present in the reservoir such that pressure in thedepleted reservoir is less than when material was present. Accordingly,pressure in an aquifer may be greater than pressure in a depletedreservoir below the aquifer. Groundwater may flow from thehigher-pressure aquifer to the lower-pressure, depleted reservoir if aflow path were provided from one reservoir to the other. A reservoir maybe defined by the inner surface of a housing and one or more surfaces ofa body, e.g., group of coupled assemblies, disposed within the housing.A reservoir may have an upper end and a lower end with walls extendingfrom or between the upper end and the lower end. Fluid may flow within areservoir. For instance, an impeller may be disposed within a reservoirsuch that turning the impeller generates differential pressure to causefluid to flow from one end of the fluid reservoir to the other. Areservoir may be in fluid communication with a flow path. Preferably, anupper end of the reservoir may be in fluid communication with an upperend of a flow path and a lower end of the fluid reservoir may be influid communication with a lower end of the flow path, thereby forming afluid circulation loop.

The term “seal” as used herein as a noun is defined as a structure thatis capable of providing sealing contact when pressed or abutted againstor otherwise in contact with some surface. A portion of the seal may becoupled to or abutted against a surface of a structure such that, insome cases, fluid is inhibited or even prevented from passing betweenthe seal and the surface of the structure. A seal may be or include, forexample, an O-ring or a packer. At least one non-limiting preferredexample of a seal is a packer which, as illustrated in some of thedrawings herein, is cylindrical and is disposed in the annular spacebetween a first conduit and a second conduit, such that there ispreferably a first annular space and a second annular space with thepacker separating the two annular spaces. In that specific embodiment,the outer surface of the packer is pressed against the inner surface ofthe first conduit, and the inner surface of the packer is pressedagainst the outer surface of the second conduit. Preferably, the packerprovides sealing contact with the surfaces of the conduits, and thusinhibits and preferably prevents fluid from passing past the areas ofsealing contact, even when there is a substantial pressure differencebetween the first and second annular spaces.

The term “packer” is to be given its usual and customary meaning withinthe oil and gas industry, encompassing any type of structure that hasbeen used in the past in oil wells and referred to as a “packer.”

The term “pump” as used herein is defined as an assembly that includes ashaft and an impeller for driving movement of an object, e.g., fluid,hydrocarbon, gas, and solids. Movement of an object may include rotationof the object on a central axis. Additionally, movement may includeradial displacement or axial displacement of an object relative toanother object. A pump may be a progressive cavity positive displacementpump having one or more rotatable portions, e.g., drive shaft and/orrotors, having fins or blades extending from each rotatable portion.Fluid may flow across vanes, e.g., fins or blades, of a pump. A pump mayinclude a housing and one or more rotatable portions, e.g., drive shaftand/or rotors, having fins or blades extending from each rotatableportion, disposed in the housing. A pump may include a pump housinghaving one or more ports disposed therethrough. The one or more portsmay extend longitudinally, e.g., parallel to the central axis of thepump, and disposed radially around the housing. The one or more portsmay have circular profiles. Alternatively, one or more ports may beelongated. The one or more ports port may extend at an angle relative tothe central axis of a pump housing. A pump may include a drive shaftassembly capable of being coupled to a shaft assembly of a motor.

The term “shaft assembly” as used herein is defined as an assemblycapable of rotating about an axis, e.g., an elongated shaft having anaxis. One type of shaft assembly may be or include a shaft and bearings.A shaft assembly may include one or more impellers coupled to a shaft. Ashaft may be rotatably coupled to a pump body and/or a motor. A shaftassembly may be formed from two coupled shaft assemblies. Torque andaxial load may be transferred from a first shaft assembly to a secondshaft assembly, e.g., rotor.

The term “shroud” as used as noun herein is defined as a housing. Ashroud is, preferably a cylindrical sleeve, configured to be filled withfluid, e.g., wellbore fluid, hydrocarbon, water, gas. A shroud is to begiven its usual and customary meaning within the oil and gas industry,encompassing any type of structure that has been used in the past in oiland/or gas wells and referred to as a “shroud.” A shroud may have acentral aperture. A shroud may have an upper opening. A shroud may havean upper aperture, e.g., for ingress of wellbore fluid. A shroud mayhave a lower aperture, e.g., for egress of wellbore fluid. A shroud mayhave disposed therein one or more electric submersible components, e.g.,motors, motor seals, sensors, packers, power sections, seal sections,and pumps. A shroud may have a first portion open to ingress of fluidand a second portion open to egress of fluid.

The term “space” as used herein means any volumetric space. For example,it may refer to some empty volume between two objects, structures,points, lines, edges, or surfaces, i.e., not occupied by any anythingsolid. A non-limiting example of space is “annular space,” e.g., thespace between the inside surface of one conduit and the outside surfaceof another conduit disposed inside the one conduit.

The term “surface” as used herein is defined as any boundary of astructure. A surface may also refer to that cylindrical area thatextends radially around a cylinder which may, for example, be part of ashaft assembly or bearing assembly. A surface may also refer to thatcylindrical area that extends radially around a cylinder which may, forexample, be part of a housing, a stator, a rotor, or a shaft assembly. A“surface” may have any geometry, e.g., curved or flat. A surface mayhave irregular contours. A surface may be formed from components, e.g.,bearing assemblies, bodies, and/or housings, coupled together. Coupledcomponents may form irregular surfaces.

The term “unitary” as used herein means having the nature, properties,or characteristics of a single unit. For example, a shaft and a rotormay be unitary where they are connected, directly or indirectly, andfulfill the intended purpose of being rotated. Also, a shaft and animpeller may be unitary where they are connected, directly orindirectly, and fulfill the intended purpose of being rotated to movefluid, e.g., water, hydrocarbon, or lubricant.

The terms “upper” and “lower” as used herein are relative termsdescribing the position of one object, thing, or point positioned in itsintended useful position, relative to some other object, thing, or pointalso positioned in its intended useful position, when the objects,things, or points are compared to distance from the center of the earth.For example, the term “upper” identifies any object or part of aparticular object that is farther away from the center of the earth thansome other object or part of that particular object, when the objectsare positioned in their intended useful positions.

The term “well” as used herein is defined as the wellbore in combinationwith any related surface equipment outside the wellbore, such as pumpsand piping, and also the area surrounding the wellbore such as theformation, including the hydraulic fractures.

The term “wellbore” as used herein is defined as the drilled elongatedcylindrical borehole extending through the formation from the surface,where the drilling was initiated, to the endpoint where the drilling wasterminated. Depending on the context, the term may also include anydownhole components placed within the borehole, e.g., casing, cement,tubing, packers, etc.

The term “wellbore fluid” means any fluid in a wellbore, includingliquid, gas, or a mixture of liquid and gas, which existed in ororiginated from a subterranean reservoir or that is or was at some pointpresent in the subterranean reservoir, including underground water whichmay be fresh, potable, or salt water.

3. Certain Specific Embodiments

The disclosure herein includes electric submersible pump assemblies andmethods for pumping wellbore fluid that may each include an electricsubmersible pump assembly which may include: a shroud that may include:a first shroud aperture; and a second shroud aperture; a first pumpdisposed in the shroud, wherein the first pump may be capable of pumpingwellbore fluid that has flowed through the first shroud aperture; and asecond pump disposed in the shroud, wherein the second pump may becapable of pumping out of the second aperture wellbore fluid that hasflowed through the first shroud aperture.

Additionally, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatmay include: a first shroud portion; and a second shroud portion; afirst pump disposed in the shroud, wherein the second pump is capable ofpumping wellbore fluid past the first shroud portion; and a second pumpdisposed in the shroud wherein the second pump is capable of pumpingwellbore fluid out through the second shroud portion.

Also, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatmay include: a first shroud aperture; and a second shroud aperture; afirst pump disposed in the shroud; a second pump disposed in the shroud,wherein the second pump may be capable of pumping wellbore fluid out ofthe second shroud aperture; a motor; and a shaft rotatably coupled tothe motor, the first pump, and the second pump.

Further, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud; afirst pump disposed in the shroud; a second pump disposed in the shroud;and an intake conduit disposed between the first pump and the secondpump, wherein the intake conduit may have: a first intake aperture influid communication with the first pump; and a second intake aperture influid communication with the second pump.

In addition, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatthat may include: a first shroud portion having a first shroud aperture;and a second shroud portion having a second shroud aperture; a firstpump disposed in the shroud, wherein the first pump may be capable ofpumping wellbore fluid that have flowed pass the second shroud portionand then through the first shroud aperture; and a second pump disposedin the shroud.

Furthermore, the disclosure herein includes electric submersible pumpassemblies and methods for pumping wellbore fluid that may each includean electric submersible pump assembly which may include: a shroud thatthat may include: a first shroud portion having a first shroud aperturecapable of receiving wellbore fluid therethrough; and a second shroudportion having a second shroud aperture capable of receiving wellborefluid therethrough; a first pump disposed in the shroud; a second pumpdisposed in the shroud; an intake conduit disposed between the firstpump and the second pump, the intake conduit having: a first intakeaperture, wherein the first pump may receive wellbore fluid entering thefirst intake aperture; and a second intake aperture, wherein the secondpump may be capable of receiving wellbore fluid that have flowed throughthe second intake aperture; a motor; a shaft rotatably coupled to themotor, the first pump, and the second pump.

Moreover, the disclosure herein includes methods for pumping wellborefluid that may each include: providing an electric submersible pumpassembly that may include: a shroud that may include: a first shroudportion; and a second shroud portion; a first pump disposed in theshroud; and a second pump disposed in the shroud; drawing wellbore fluidfrom the wellbore into the shroud; pumping, with the first pump, aportion of the wellbore fluid in the shroud in a first direction;pumping, with the second pump, a portion of the wellbore fluid in theshroud in a second direction, opposite the first direction.

The disclosure herein includes methods for pumping wellbore fluid thatmay each include: providing an electric submersible pump assembly thatmay include: a shroud that may include: a first shroud aperture; and asecond shroud aperture; a first pump disposed in the shroud; a secondpump disposed in the shroud; a motor; and a shaft rotatably coupled tothe motor, the first pump, and the second pump; rotating the shaft withmotor; actuating the first pump and the second pump with the rotatingshaft; pumping, with the actuated first pump, wellbore fluid in a firstdirection; pumping, with the actuated second pump, wellbore fluid in theshroud in a second direction, opposite the first direction.

Any one of the electric submersible pump assemblies or methods disclosedherein may further include a shaft rotatably coupled to the first pumpand the second pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first pump and the second pump may be disposedbetween the first shroud aperture and the second shroud aperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second pump may be below the first pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first pump may be capable of pumping wellborefluid away from the second pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second pump may be capable of pumping wellborefluid away from the first pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first pump may be capable of pumping wellborefluid in a first direction and the second pump may be capable of pumpingwellbore fluid in a second direction that is opposite the firstdirection.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second pump may be capable of pumping wellborefluid away from the first pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first shroud portion may have a first shroudaperture through which wellbore fluid is capable of flowing into theshroud.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second shroud portion has a second shroud aperturethrough which wellbore fluid is capable of flowing out of the shroud.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first pump may be between the first shroud portionand the second pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second pump may be between the first pump and thefirst shroud portion.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the motor, the first pump, and the second pump aredisposed between the first shroud aperture and the second shroudaperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second pump is capable of pumping through thesecond shroud aperture wellbore fluid that have flowed through the firstshroud aperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first pump is above the second pump.

Any one of the electric submersible pump assemblies or methods disclosedherein may further include a packer disposed in the shroud, where thepacker is capable of inhibit wellbore fluid flow pass the packer.

Any one of the electric submersible pump assemblies or methods disclosedherein may further include a packer disposed in the shroud above themotor.

Any one of the electric submersible pump assemblies or methods disclosedherein may further include a shaft rotatably coupled to the first pumpand the second pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the motor may be below the second pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first intake aperture may have a first radiuslarger a second radius of the second intake aperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first intake aperture may be above the secondintake aperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, wellbore fluid flowing through the second intakeaperture may flow upwardly.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the wellbore fluid flowing through the second intakeaperture may be capable of exiting the second shroud aperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the wellbore fluid flowing through the first intakeaperture may flow towards the first pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the wellbore fluid flowing through the second intakeaperture may flow downwardly.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the wellbore fluid entering the second intake aperturemay flow towards the second pump.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the wellbore fluid entering the first shroud aperturemay be capable of entering the first intake aperture and the secondintake aperture.

Any one of the electric submersible pump assemblies or methods disclosedherein may further include a packer disposed in the shroud below theintake conduit.

Any one of the electric submersible pump assemblies or methods disclosedherein may further include a packer disposed in the shroud above themotor.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second pump may be capable of pumping out of thesecond shroud aperture wellbore fluid that has flowed through the firstshroud aperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first pump may be above the intake conduit.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first pump may below the intake conduit.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the first intake aperture has a first diameter thatmay be greater than second diameter of the second intake aperture.

In any one of the electric submersible pump assemblies or methodsdisclosed herein, the second shroud aperture may extend perpendicularlyto a central axis of the shroud.

4. Specific Embodiments in the Drawings

The drawings presented herein are for illustrative purposes only and donot limit the scope of the disclosure or claims. Rather, the drawingsare intended to help enable one having ordinary skill in the art to makeand use the systems and assemblies and practice the methods disclosedherein.

This section addresses specific versions of electric submersible pumpassemblies shown in the drawings, which include assemblies, elements andparts that can be part of one or more downhole wellbore systems ordownhole methods for generating electricity. Although this sectionfocuses on the drawings herein, and the specific embodiments found inthose drawings, parts of this section may also have applicability toother embodiments not shown in the drawings. The limitations referencedin this section should not be used to limit the scope of the claimsthemselves, which have broader applicability than the structuresdisclosed in the drawings.

FIG. 1 illustrates a cross-sectional side view of an electricsubmersible pump (ESP) assembly 100 disposed in a wellbore. FIG. 1depicts a wellbore that is a vertical wellbore, but it is understoodthat the ESP assembly 100 may also be used in a horizontal wellbore. Acasing 102 lines inner surfaces of the wellbore for reinforcement. TheESP assembly 100 may be coupled, e.g., via a bolt on discharge head 104,to tubing extending from surface. The ESP assembly 100 may include aproduction pump 200, an intake conduit 300, an inverted pump 400, apacker 500, a discharge conduit 600, a motor 700, and a shroud 800. Anupper end of the production pump 200 is coupled, e.g., via threads, tothe bolt on discharge head 104. A lower end of the production pump 200is coupled, e.g., via bolts, to an upper end of the intake conduit 300.A lower end of the of the intake conduit 300 is coupled, e.g., viabolts, to an upper end of the inverted pump 400. A lower end of theinverted pump 400 is coupled, e.g., via bolts, to an upper end of thepacker 500. A lower end of the packer 500 is coupled, e.g., via bolts,to an upper end of the discharge conduit 600. A lower end of thedischarge conduit 600 is coupled, e.g., via bolts, to an upper end ofthe motor 700.

Additional components such as sensors, e.g., temperature sensors, flowrate sensors, and pressure sensors, may be included on the ESP assembly100. Those additional components along with the production pump 200, theintake conduit 300, the inverted pump 400, the packer 500, the dischargeconduit 600, and the motor 700 are coupled to form a string disposed inthe shroud 800. The shroud 800 is an elongated housing that has an uppershroud portion and a lower shroud portion. The upper shroud portion iscoupled to a shroud hanger 106 that is coupled to the tubing extendingfrom surface. The lower shroud portion has one or more exit ports 802extending therethrough.

That ESP assembly 100 preferably has an annular space between the shroud800 and the string of the production pump 200, the intake conduit 300,the inverted pump 400, the discharge conduit 600, the motor 700, and oneor more sensors. The annular space provides passage for wellbore fluidthat may enter the shroud 800. Fluid in the annular space may furtherflow through interiors of the production pump 200, the intake conduit300, the inverted pump 400, and the discharge conduit 600 and,afterwards, flow out the one or more exit ports 802 of the shroud 800.In other words, the production pump 200, the intake conduit 600, theinverted pump 400, and the discharge conduit 600 are conduits thatprovide passage for any wellbore fluid flowing in the shroud 800.

The production pump 200, the intake conduit 300, the inverted pump 400,the packer 500, the discharge conduit 600, and the motor 700, each has arotatable shaft assembly disposed therein (see FIGS. 2-6 ). Each shaftassembly is rotatably coupled to one or more bearings that are coupledto inner surfaces of a respective component. Furthermore, the shaftassemblies are coupled in series to form one long shaft assembly. Forexample, the shaft assemblies in the production pump 200, the intakeconduit 300, the inverted pump 400, the packer 500, the dischargeconduit 600, and the motor 700 are coupled to form one long shaftassembly. Moreover, rotation of any one shorter, individual shaftassembly would rotate the entire shaft assembly. For example, the longshaft assembly may be rotated by the motor 700 because a shorter shaftassembly disposed in the motor.

Additionally, the shaft assemblies in the production pump 200 and theinverted pump 400 each include impellers (see FIG. 2 and FIG. 4 ). Theimpellers in the production pump 200 and the inverted pump 400 aresized, shaped, and configured to push fluid, e.g., hydrocarbon, throughthe respective production pump 200 and inverted pump 400. Preferably,the impeller in the production pump 200 are angled relative to thecentral axis of the production pump 200 to push fluid towards surface,e.g., upwardly. Whereas the impeller in the inverted pump 400 are angledrelative to the central axis of the inverted pump 400 to push fluidfurther downhole, e.g., downwardly.

FIG. 2 illustrates a cross-sectional side view of a production pump 200.The production pump 200 of FIG. 2 may be used with the ESP assembly 100of FIG. 1 . The production pump 200 may receive fluid flowingtherethrough. The production pump 200 includes a production pump housing202 having an inner surface and an outer surface. The production pumphousing 202 surrounds internal components and assemblies. The innersurface of the production pump housing 202 defines a fluid reservoir 204that is configured to receive wellbore fluid, e.g., hydrocarbon. Thefluid reservoir 204 has an upper end and a lower end. Arrows in FIG. 2indicate fluid flow through the fluid reservoir 204 from the lower endtowards the upper end of the production pump 200.

A body is disposed within and is coupled to the production pump housing202. The body includes several internal components coupled together.When assembled and coupled to the production pump housing 202, theinternal components form the body inside the production pump housing202. The assembled components align to form a fluid reservoir 204 in thebody. As indicated by arrows in FIG. 2 , fluid may flow through thefluid reservoir 204.

A shaft assembly is disposed within the internal assembly in the fluidreservoir 204. The shaft assembly includes a shaft 206, and impeller 208coupled to the outer surface of the shaft 206.

The impeller 208 is coupled to the shaft 206. Additionally, the impeller208 is disposed in the fluid reservoir 204. Thus, as fluid flow throughthe fluid reservoir 204 and across the impeller 208, the flowing fluidwould cause the impeller 208 to rotate. Accordingly, the shaft 206 wouldalso be rotated.

Rotation of the impeller 208 may produce an area of low pressure abovethe impeller 208 and an area of high pressure below the impeller 208,thereby creating differential pressure in the fluid reservoir 204. Thedifferential pressure may cause fluid to flow in a path from the area ofhigh pressure to the area of low pressure, as indicated by arrows inFIG. 2 .

The upper end of the production pump 200 has an opening for fluid toexit the production pump 200. Thus, fluid flowing through the fluidreservoir 204 may exit the production pump housing 202 through theopening.

FIG. 3 illustrates a cross-sectional side view of an intake conduit 300disposed in a shroud 800. The intake conduit 300 of FIG. 3 may be usedwith the ESP assembly 100 of FIG. 1 . The intake conduit 300 is acylindrical body having a borehole extending therethrough. In addition,the intake conduit 300 has one or more upper entry ports 302 and one ormore lower entry ports 304 that are in fluid communication with theborehole.

The one or more upper entry ports 302 extend through the body of theintake conduit 300 at an angle to the central axis of the of the intakeconduit 300. The one or more lower entry ports 304 also extend throughthe cylindrical body of the intake conduit 300 at an angle, e.g., 90degrees or less, to the central axis of the of the intake conduit 300.However, the direction the one or more upper entry ports 302 extends,e.g., upwardly, is opposite to the one or more lower entry ports 304extends, downwardly. Thus, when fluid flow through the one or more upperentry ports 302, the fluid would flow in an upwardly direction.Conversely, fluid flow through the one or more lower entry ports 304,the fluid would flow in an upwardly direction.

Additionally, each upper entry port 302 has a diameter greater than adiameter of each lower entry port 304. Thus, more fluid could flowthrough an upper entry port 302 a lower entry port 304.

A screen 306 is disposed around the one or more upper entry ports 302and the one or more lower entry ports 304. The screen 306 has one ormore slits disposed therethrough. The one or more slits are size,shaped, and configured to allow fluid to flow through the screen 306 butinhibit debris larger than the one or more slits from passing through.

A shaft assembly is disposed in the borehole of the intake conduit 300.The shaft assembly includes a shaft 308 and one or more bearings 310.The shaft 312 is rotatably coupled to the one or more bearings 310 suchthat the shaft 312 is rotatable relative to the intake conduit 300.

FIG. 4 illustrates a cross-sectional side view of an inverted pump 400.The inverted pump 400 of FIG. 4 may be used with the ESP assembly 100 ofFIG. 1 . The inverted pump 400 may receive fluid flowing therethrough.The inverted pump 400 includes an inverted pump housing 402 having aninner surface and an outer surface. The inverted pump housing 402surrounds internal components and assemblies. The inner surface of theinverted pump housing 402 defines a fluid reservoir 404 that isconfigured to receive wellbore fluid, e.g., hydrocarbon. The fluidreservoir 404 has an upper end and a lower end. Arrows in FIG. 4indicate fluid flow through the fluid reservoir 404 from the upper endtowards the lower end of the inverted pump 400.

A body is disposed within and is coupled to the inverted pump housing402. The body includes several internal components coupled together.When assembled and coupled to the inverted pump housing 402, theinternal components form the body inside the inverted pump housing 402.The assembled components align to form a fluid reservoir 404 in thebody. As indicated by arrows in FIG. 4 , fluid may flow through thefluid reservoir 404.

A shaft assembly is disposed within the internal assembly in the fluidreservoir 404. The shaft assembly includes a shaft 406, and an impeller408 coupled to the outer surface of the shaft 406.

The impeller 408 is coupled to the shaft 406. Additionally, the impeller408 is disposed in the fluid reservoir 404. Thus, as fluid flow throughthe fluid reservoir 404 and across the impeller 414, the flowing fluidwould cause the impeller 408 to rotate. Accordingly, the shaft 406 wouldalso be rotated.

Rotation of the impeller 408 may produce an area of high pressure abovethe impeller 408 and an area of low pressure below the impeller 408,thereby creating differential pressure in the fluid reservoir 404. Thedifferential pressure may cause fluid to flow in a path from the area ofhigh pressure to the area of low pressure, as indicated by arrows inFIG. 4 .

The lower end of the inverted pump 400 has an opening for fluid to exitthe inverted pump 400. Thus, fluid flowing through the fluid reservoir404 may exit the inverted pump housing 402 through the opening.

FIG. 5 illustrates a cross-sectional side view of a packer 500 disposedin a shroud 800. The packer 500 of FIG. 5 may be used with the ESPassembly 100 of FIG. 1 . The packer 500 is a cylindrical body having aborehole extending therethrough. The packer 500 includes a seal 502 anda bracket 504. The bracket 504 may be tightened to cause the seal 502 tobulge outward. Thus, the bulging seal 502 is abutted against internalsurfaces of the cylindrical body and is compressed against a motor leadextension, e.g., power cable, traveling through the seal 502.

A shaft assembly is disposed in the borehole of the packer 500. Theshaft assembly includes a shaft 506 and one or more bearings 508. Theshaft 506 is rotatably coupled to the one or more bearings 508 such thatthe shaft 506 is rotatably relative to the packer 500.

FIG. 6 illustrates a cross-sectional side view of a discharge conduit600 disposed in shroud 800. The discharge conduit 600 of FIG. 6 may beused with the ESP assembly 100 of FIG. 1 . The discharge conduit 600 isa cylindrical body having a borehole extending therethrough. Inaddition, the discharge conduit 600 has one or more discharge ports 602that are in fluid communication with the borehole. The one or moredischarge ports 602 extend through the cylindrical body of the dischargeconduit 600 at an angle, e.g., 90 degrees or less, to the central axisof the of the discharge conduit 600. Preferably, the one or moredischarge ports 602 extends in downwardly direction. Thus, when fluidflow through the one or more e discharge ports 602, the fluid would flowin a downwardly direction.

A shaft assembly 604 is disposed in the borehole of the dischargeconduit 600. The shaft assembly includes a shaft 604 and one or morebearings 606. The shaft 604 is rotatably coupled to the one or morebearings 606 such that the shaft 604 is rotatably relative to thedischarge conduit 600.

Referring to FIGS. 1-6 , operation of an ESP assembly 100 in a downholewellbore is as follow. First, fluid from an underground reservoir (notshown) may enter the wellbore through perforations (not shown) createdin a casing 102 that lines the wellbore. Pressure in the wellbore islower than pressure in the underground reservoir, so the wellbore fluidwould migrate into the casing 200 until pressure in the wellbore and theunderground reservoir equalizes. Next, an operator may lower an ESPassembly 100 into wellbore fluid that have entered the wellbore, whichwould then enter and fill the ESP assembly 100. The ESP assembly 100 hasan outer diameter smaller than an inner diameter of the casing 102;therefore, a first annular space would exist between the ESP assembly100 and the casing 102. Preferably, the ESP assembly 100 is disposedabove the perforations in the casing 102 but is submerged in thewellbore fluid. Then, the operator may actuate the production pump 200and the inverted pump 400 to cause wellbore fluid to be drawn into theESP assembly 100.

As shown by the arrows in FIGS. 1-6 , the actuated production pump 200and inverted pump 400 would draw upwardly fluid that would have enteredthe casing 102 from the perforations (not shown) below the ESP assembly100. The fluid would flow upwardly through the first annular spacebetween the wellbore and the outside surfaces of the shroud 800. At anupper edge of the shroud 800, the wellbore fluid would then flow throughan opening in the upper portion of the shroud 800 and down a portion ofthe second annular space that is disposed between inner surfaces of theshroud 800 and a string formed by the production pump 200 the intakeconduit 400. Because the wellbore fluid may be multiphase (e.g.,including liquid hydrocarbon, solid debris entrained in the liquidhydrocarbon, and gas), mostly liquid hydrocarbon (having solid debris)would flow down the portion of the second annular space towards theintake conduit 300. Lighter gas from the wellbore fluid would separatefrom the liquid hydrocarbon and would continue rising upwardly pass theshroud 800. The rising gas may be collected in a receptacle (not shown)disposed above the ESP assembly 100.

Because a seal 502 of a packer 500 is pressed against the shroud 800,the liquid hydrocarbon cannot flow pass the seal 502 in the secondannular space. The portions of the seal 502 that are pushed against theshroud 800 may inhibit fluid flow pass the seal 502. Accordingly, theportions of the seal 502 that are pushed against the shroud 800 woulddivide a second annular space disposed between the shroud 800 and astring formed by a production pump 200, an intake conduit 300, aninverted pump 400, a packer 500, a discharge conduit 600, and a motor700. Accordingly, the liquid hydrocarbon may only flow through theintake conduit 300.

At the intake conduit 300, the liquid hydrocarbon may flow through oneor more slits in a screen 306 that is disposed around a cylindrical bodyof the intake conduit 300. The one or more slits in the screen 306 aresized, shaped, and configured to filter certain solid debris entrainedin the liquid hydrocarbon from passing through.

For the liquid hydrocarbon that may flow through the screen 306, a firstportion of the liquid hydrocarbon may flow through one or more upperentry ports 302 and a second portion of the liquid hydrocarbon may flowthrough one or more lower entry ports 304. Each upper entry port 302 hasa diameter greater than a diameter of each lower entry port 304.Accordingly, more volume of liquid hydrocarbon could flow through theupper entry ports 302 than volume of liquid hydrocarbon that could flowthrough the lower entry ports 304.

For liquid hydrocarbon that may flow through the one or more upper entryports 302, the production pump 200 would pump the liquid hydrocarbontowards surface, e.g., via tubing coupled to the production pump 200.

For liquid hydrocarbon that may flow through the one or more lower entryports 304, the inverter pump 400 would pump the liquid hydrocarbon downand through a borehole of the packer 800 into a discharge conduit 600.The liquid hydrocarbon would exit one or more discharge ports 602disposed in the discharge conduit 600. The liquid hydrocarbon wouldfurther flow down the second annular space and across outer surfaces ofthe motor 700.

During operation, the motor 700 may generate heat. If not dissipated,the heat could damage the motor 700. Thus, liquid hydrocarbon that flowacross the outer surfaces of the motor 700 may be used to absorb heatgenerated by the motor 700. The heated liquid hydrocarbon may flow awayfrom the motor 700; thereby, carrying heat away from the motor 700.

Furthermore, the heated liquid hydrocarbon may flow out of the shroud800 through exit ports 116 disposed in the shroud 800. After exiting theshroud 800, the heated liquid hydrocarbon may mix with cooler wellborefluid that may have entered the casing 102 from the reservoir.

What is claimed as the invention is:
 1. An electric submersible pumpassembly for pumping fluids from a wellbore, comprising: a shroud thatcomprises: a first shroud aperture; and a second shroud aperture; afirst pump disposed in the shroud, wherein the first pump is capable ofpumping wellbore fluid that has flowed through the first shroudaperture; and a second pump disposed in the shroud, wherein the secondpump is capable of pumping out of the second aperture wellbore fluidthat has flowed through the first shroud aperture.
 2. The electricsubmersible pump assembly of claim 1, further comprising a shaftrotatably coupled to the first pump and the second pump.
 3. The electricsubmersible pump assembly of claim 1, wherein the first pump and thesecond pump are disposed between the first shroud aperture and thesecond shroud aperture.
 4. The electric submersible pump assembly ofclaim 1, wherein the second pump is below the first pump.
 5. Theelectric submersible pump assembly of claim 1, wherein the first pump iscapable of pumping wellbore fluid away from the second pump.
 6. Theelectric submersible pump assembly of claim 1, wherein the second pumpis capable of pumping wellbore fluid away from the first pump.
 7. Theelectric submersible pump assembly of claim 1, wherein the first pump iscapable of pumping wellbore fluid in a first direction and the secondpump is capable of pumping wellbore fluid in a second direction that isopposite the first direction.
 8. The electric submersible pump assemblyof claim 1, wherein the second pump is capable of pumping wellbore fluidaway from the first pump.
 9. An electric submersible pump assembly forpumping fluids from a wellbore, comprising: a shroud that comprises: afirst shroud portion; and a second shroud portion; a first pump disposedin the shroud, wherein the second pump is capable of pumping wellborefluid past the first shroud portion; and a second pump disposed in theshroud wherein the second pump is capable of pumping wellbore fluid outthrough the second shroud portion.
 10. The electric submersible pumpassembly of claim 9, wherein the first shroud portion has a first shroudaperture through which wellbore fluid is capable of flowing into theshroud.
 11. The electric submersible pump assembly of claim 9, whereinthe second shroud portion has a second shroud aperture through whichwellbore fluid is capable of flowing out of the shroud.
 12. The electricsubmersible pump assembly of claim 9, wherein the first pump is betweenthe first shroud portion and the second pump.
 13. The electricsubmersible pump assembly of claim 9, wherein the second pump is betweenthe first pump and the first shroud portion.
 14. An electric submersiblepump assembly for pumping fluids from a wellbore, comprising: a shroudthat comprises: a first shroud aperture; and a second shroud aperture; afirst pump disposed in the shroud; a second pump disposed in the shroud,wherein the second pump is capable of pumping wellbore fluid out of thesecond shroud aperture; a motor; and a shaft rotatably coupled to themotor, the first pump, and the second pump.
 15. The electric submersiblepump assembly of claim 14, wherein the motor is below the second pump.16. The electric submersible pump assembly of claim 14, wherein thesecond pump is capable of pumping out of the second shroud aperturewellbore fluid that has flowed through the first shroud aperture.
 17. Anelectric submersible pump assembly for pumping fluids from a wellbore,comprising: a shroud; a first pump disposed in the shroud; a second pumpdisposed in the shroud; and an intake conduit disposed between the firstpump and the second pump, the intake conduit having: a first intakeaperture in fluid communication with the first pump; and a second intakeaperture in fluid communication with the second pump.
 18. The electricsubmersible pump assembly of claim 17, wherein the first pump is abovethe intake conduit.
 19. The electric submersible pump assembly of claim17, wherein the first pump is below the intake conduit.
 20. The electricsubmersible pump assembly of claim 17, wherein the first intake aperturehas a first diameter that is greater than second diameter of the secondintake aperture.